In the oil and gas industry, one widely used technique to search for oil and/or gas is to conduct seismic surveys to study subsurface formations. Typically, in seismic surveys, geophysicists use “seismic reflection” techniques to produce an image of the subsurface formations. These techniques generally involve emitting acoustic signals from a seismic energy source that propagate into the earth and recording the signals that are at least partially reflected by the layers of the subsurface formation that have different acoustic impedances. The acoustic waves reflected toward the surface are recorded as a function of time by the receivers. The signals recorded by the receivers are often called seismic traces.
Seismic data can be obtained in marine or land operations and the equipment used in each situation varies depending on the needs of the operation. Generally, the receivers used in seismic surveying include hydrophones and geophones. A hydrophone is a pressure-sensitive seismic detector that is typically used as receivers in marine seismic data acquisition because it enables recording of acoustic energy underwater by converting acoustic energy into electrical energy. Most hydrophones are based on a piezoelectric transducer that generates electricity when subjected to a pressure change. Such piezoelectric materials, or transducers, can convert a sound signal into an electrical signal.
A geophone is a velocity-sensitive seismic detector that is typically used as receivers in land or marine seismic data acquisition because it converts movement, e.g., displacement, into electrical energy—voltage, which may be recorded. Geophones have historically been passive analog devices and typically comprise a spring-mounted magnetic mass moving within a wire coil to generate an electrical signal. For land acquisition, the geophone contacts the ground and thus, its magnet, as the Earth moves, moves up and down around the mass. The magnetic field of this moving magnet produces an electrical voltage in the wire. The response of a coil/magnet geophone is proportional to ground velocity.
Once the seismic traces are acquired, various processing techniques are conventionally applied to these traces to improve the signal to noise ratio and facilitate their interpretation to provide a model of the subsurface formation. These processing techniques are applied to seismic traces with the goal of producing detailed and accurate models for use in interpreting subsurface geologic structures. Such detailed and accurate models are important in various fields. Specifically in the oil and gas industry, they are generally used for reservoir characterization, such as lithology, fluid prediction, and pore pressure prediction, as well as reservoir volume estimation.
Typically, processing of seismic traces (raw data) begins with deconvolution and other processes, which often improves temporal resolution by collapsing the seismic wavelet to approximately a spike and suppressing reverberations on some field data and remove noise. Migration is typically performed towards the end of the processing sequence. Migration generally corrects and improves initial assumptions that the surveyed formation contains near-horizontal layers. Particularly, seismic migration attempts to model actual geophysical characteristics of the formation, which can include dips, discontinuities, and curvature of the formation. Seismic migration typically occurs towards the end of the image processing of seismic traces. Further, migration generally moves dipping reflections to their true subsurface positions and collapses diffractions. As such, the process of migration is an imaging process that yields a seismic image of the subsurface. Migration can be performed before or after the stacking of the traces. Typically, there are two types of seismic migration: time migration and depth migration. The type depends on whether the output traces are represented according to the time or the depth.
Further, current migration methods do not have the capability to address complex non-horizontal features of the formation, including steeply dipping reflectors such as salt flanks. For instance, standard wave equation techniques used in conventional migration methods utilize mathematical approximations that assume wavefields propagate in only one direction. These techniques become inapplicable for complex situations because the integrity of these wave equation approximations breaks down as the dip angle goes beyond 70 degrees. One way of overcoming the limitations of the current state of the art of seismic migration is to apply reverse time migration (RTM) to the seismic data. RTM can handle complex wave velocities to produce all kinds of acoustic waves, such as reflections, refractions, diffractions, multiples, evanescent waves. Further, it can correct propagation amplitude and imposes no dip limitations on the image.
Because RTM enables structures with complex features to be properly imaged, RTM is a useful tool to address the complex non-horizontal features of a particular formation. In theory, RTM provides a more accurate model of the subsurface formations. In practice, however, RTM requires significantly more computational power than other techniques, which can be very costly, especially when applied to a TTI (Tilted Transverse Isotropy) project. As such, the cost to run the RTM algorithms may, often times, outweigh the benefits that RTM processing provides.
Typically, RTM inputs comprises: an initial inversion of the medium to be analyzed, a wavelet, and the set of recorded acoustic wave pressure traces. Generally, RTM simulates, in mathematical terms, the propagation of the acoustic wave in the medium being analyzed. During the simulation, the first step begins with exciting the medium by introducing a wavelet, or a shot, which can be expressed as a function of frequency and time. Then, RTM mathematically simulates wave propagation (forward propagation) by using an acoustic wave equation. Then, RTM repeats these steps in reverse, where it begins with the data recorded by the receivers and propagates the wave field back in time (backward propagation). When both fields representing the forward and backward propagations are available, the last step is to cross-correlate the two propagations to generate the output image.
The current state of the art is to use the known two-way acoustic wave equation of:
            1              c        2              ⁢                            ∂          2                ⁢        u                    ∂                  t          2                      =                    ∇        2            ⁢      u        +    s  
where:                u=u(x,y,z,t) and is the pressure field,        c=c(x,y,z) and is the velocity field, and        s=s(x,y,z,t) is the source term.        
There are, however, disadvantages to applying RTM to seismic traces using the conventional two-way acoustic wave equation. One of the disadvantages is the amount of computational power required to apply such algorithms. Other known methods such as phase encoding and delayed-shot migration and plane-wave migration do not address these problems as phase encoding is dependent on stacking power to remove the cross-talk artifacts and the delayed-shot and plane wave migration methods required expensive computation for RTM.
The novel approach of the present invention overcomes these problems associated with methods known in the art. For example, the present invention introduces a phase-encoding algorithm, harmonic source migration, that is generalized to a 3-D harmonic-source migration. The introduction of the “harmonic-source” phase encoding harmonic source migration improves the efficiency of the RTM method without compromising the processed data quality, thereby reducing computational costs, by reducing the number of shots, and hence the project cycle time and cost. In addition, by generalizing it to 3D harmonic-source migration, the requirement that all the sources are along a straight line is eliminated. Instead, the present invention—3D harmonic-source reverse time migration—only requires that all the sources and receivers are on a flat plane. This requirement is generally satisfied by most streamer acquisition in marine seismic surveys. The present invention can be used with other marine and seismic surveying methods that meet this requirement, and is not limited to only data from streamer acquisition.
Further, the 3D harmonic-source migration provided by the claimed invention is more appropriate for current wide-azimuth or multi-azimuth acquisitions, while 2D harmonic-source migration mainly fits to narrow azimuth migration. Also, a 3D harmonic-source migration allows for adjusting of sources and receivers to generate artificial sources (split spread), and migrating them altogether to obtain superior image without additional cost. In addition, for each 3D harmonic-source migration, the image produced can cover the whole area that has been surveyed and provides a full line migration aperture. On the other hand, for other known migration techniques such as common-shot migration, the migration aperture is limited in both directions and may fail to image the dipping events in far offsets.
In view of the drawbacks of methods known in the art, there is a great need for systems and methods that provide efficient and cost effective reverse time migration of seismic data. The present disclosure provides for improved methods and systems that produce high quality reverse time migration data without reduced computational costs and time.